This Invention relates to the stimulation of hydrocarbon wells and in particular to the fluids and methods used in treating a damaged formation using acid-type fluids, and other fluids of similar function.
1. Introduction to the Technology
Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a xe2x80x9creservoirxe2x80x9d) by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the oil to reach the surface. In order for oil to be xe2x80x9cproduced,xe2x80x9d that is travel from the formation to the wellbore (and ultimately to the surface) there must be a sufficiently unimpeded flowpath from the formation to the wellbore. This flowpath is through the formation rockxe2x80x94e.g., sandstone, carbonatesxe2x80x94which has pores of sufficient size and number to allow a conduit for the oil to move through the formation.
Hence, one of the most common reasons for a decline in oil production is xe2x80x9cdamagexe2x80x9d to the formation that plugs the rock pores and therefore impedes the flow of oil. This damage generally arises from another fluid deliberately injected into the wellbore, for instance, drilling fluid. Even after drilling, some drilling fluid remains in the region of the formation near the wellbore, which may dehydrate and form a coating on the wellbore. The natural effect of this coating is to decrease permeability to oil moving from the formation in the direction of the wellbore.
Another reason for lower-than-expected production is that the formation is naturally xe2x80x9ctight,xe2x80x9d (low permeability formations) that is, the pores are sufficiently small that the oil migrates toward the wellbore only very slowly. The common denominator in both cases (damage and naturally tight reservoirs) is low permeability. Techniques performed by hydrocarbon producers to increase the net permeability of the reservoir are referred to as xe2x80x9cstimulation.xe2x80x9d Essentially, one can perform a stimulation technique by: (1) injecting chemicals into the wellbore to react with and dissolve the damage (e.g., wellbore coating); (2) injecting chemicals through the wellbore and into the formation to react with and dissolve small portions of the formation to create alternative flowpaths for the hydrocarbon (thus rather than removing the damage, redirecting the migrating oil around the damage); or (3) injecting chemicals through the wellbore and into the formation at pressures sufficient to actually fracture the formation, thereby creating a large flow channel though which hydrocarbon can more readily move from the formation and into the wellbore. The present Invention is directed primarily to the second of these three processes.
Thus, the present Invention relates to methods to enhance the productivity of hydrocarbon wells (e.g., oil wells) by removing (by dissolution) near-wellbore formation damage or by creating alternate flowpaths by dissolving small portions of the formation. Generally speaking, acids, or acid-based fluids, are useful in this regard due to their ability to dissolve both formation minerals and contaminants (e.g., drilling fluid coating the wellbore or that has penetrated the formation) which were introduced into the wellbore/formation during drilling or remedial operations.
2. The Prior Art
At present, acid treatments are plagued by three serious limitations: (1) radial penetration; (2) axial distribution; and (3) corrosion of the pumping and well bore tubing. The first problem, radial penetration, is caused by the fact that as soon as the acid is introduced into the formation (or wellbore) it reacts very quickly with the wellbore coating, or formation matrix (e.g., sandstone or carbonate). In the case of treatments within the formation (rather than wellbore treatments) the formation near the wellbore that first contacts the acid is adequately treated, though portions of the formation more distal to the wellbore (as one moves radially, outward from the wellbore) remain untouched by the acidxe2x80x94since all of the acid reacts before it can get there. For instance, sandstone formations are often treated with a mixture of hydrofluoric and hydrochloric acids at very low injections rates (to avoid fracturing the formation). This acid mixture is often selected because it will dissolve clays (found in drilling mud) as well as the primary constituents of naturally occurring sandstones (e.g., silica, feldspar, and calcareous material). In fact, the dissolution is so rapid that the injected acid is essentially spent by the time it reaches a few inches beyond the wellbore. Thus, it has been calculated that 117 gallons of acid per foot is required to fill a region five feet from the wellbore (assuming 20% porosity and 6-inch wellbore diameter). See, Acidizing Fundamentals, 5,6, In Acidizing Fundamentals SPE (1994). Yet, a far greater amount of acid would that this would be required to achieve radial penetration of even a single foot, if a conventional fluid (HCl) were used. Similarly, in carbonate systems, the preferred acid is hydrochloric acid, which again, reacts so quickly with the limestone and dolomite rock, that acid penetration is limited to a few inches to a few feet. In fact, due to such limited penetration, it is believed matrix treatments are limited to bypassing near-wellbore flow restrictionsxe2x80x94i.e., they do not provide significant stimulation beyond what is achieved through (near-wellbore) damage removal. Yet damage at any point along the hydrocarbon flowpath can impede flow (hence production). Id. Therefore, because of the prodigious fluid volumes required, these treatments are severely limited by their cost.
In response to this xe2x80x9cradial penetrationxe2x80x9d problem, organic acids (e.g., formic acid, acetic acid) are sometimes used, since they react more slowly than mineral acids such as HCl. Organic acids are an imperfect solution thoughxe2x80x94since they react incompletely, plus they are expensive.
A third general class of acid treatment fluids (the first two being mineral acids and organic acids) have evolved in response to the need to reduce corrosivity and prolong the migration of unspent acid radially away from the wellbore. This second general class of compounds are often referred to as xe2x80x9cretarded acid systems.xe2x80x9d The common idea behind these systems is that the acid reaction rate is slowed down for instance, by gelling the acid, oil-wetting the formation, or emulsifying the acid with an oil. Each of these approaches also has significant problems which limit their use.
Gelling agents, though they should, in theory, retard acid reaction rate, are seldom used in matrix acidizing since the increased viscosity makes the fluid more difficult to pump. Similarly, chemically retarded acids (e.g., prepared by adding an oil-wetting surfactant to acid in an effort to create a barrier to acid migration to the rock surface) often require continuous injection of oil during the treatment. Moreover these systems are often ineffective at high formation temperatures and high flow rates since absorption of the surfactant on the formation rock is diminished. Emulsified acid systems are also limited by increased frictional resistance to flow.
The second significant limitation of acid treatments is axial distribution. This refers to the general desirability to limit the movement of the acid solution axially, so that it does not intrude upon other zones, in particular, water-saturated zones. Any fluid that migrates away from its intended target (i.e., the desired hydrocarbon flowpath, or the damaged region) means that more fluid must be pumped into the formation, therefore increasing treatment cost. A conventional mineral acid treatment (e.g., HCl) has very high miscibility with an aqueous phase relative to the organic- (or hydrocarbon-) bearing phase, and therefore the potential (and undesirable) migration of the HCl-based fluid into a water-saturated zone, is a serious concern. Therefore, an acid fluid having very low miscibility with an aqueous (water) phase is highly desirable.
Another ubiquitous problems that limits the desirability of acid treatments is the corrosion of the pumping equipment and well casings, caused by contact with the acid (worse in the case of more concentrated solutions of mineral acids. To solve the corrosion problem, conventional acid treatments often add a corrosion inhibitor to the fluid; however, this can significantly increase the cost of a matrix acidizing treatment.
The point of novelty of the present Invention resides in the incorporation of an extraordinary family of compounds into fluids for various stimulation and workover techniques. The family of compounds is known generally as xe2x80x9cionic liquids.xe2x80x9d This term refers to compounds that: (1) are liquid at ambient temperatures; and (2) are composed entirely of cations and anions (as opposed to a molecular liquid, such as benzene, or an ionic solution, such as Na+ Clxe2x88x92 dissolved in water). Though matrix treatment fluidsxe2x80x94nor indeed, any fluids related to oilfield applicationsxe2x80x94that incorporate ionic liquids have not been disclosed prior to the present Invention, ionic fluids are known substances.
Among the first to disclose ionic liquids were Hurley and Weir in a family of United States Patent applications, including, U.S. Pat. Nos. 2,446,331; 2,446,339; and 2,446,350, that issued about 40 years ago. These applications disclosed ionic liquids for use as conducting baths in aluminum electroplating. Over the years, new species of ionic liquids have been identified, and new applications for them have emerged. These include: support for catalysis; an organic solvent in catalysis, organic synthesis, and chemical separations; electroplating, and non-aqueous batteries. See, e.g., U.S. Pat. No. 5,827,602, Hydrophobic Ionic Liquids, assigned by Covalent Associates Incorporated (1998); and, M. Freemantle, Designer Solvents: Ionic Liquids May Boost Clean Technology Development, Chem. and Engr. News London, Mar. 30, (1998).
The primary fluids used in acid treatments are mineral acids such as hydrochloric acid, which was disclosed as the fluid of choice in a patent issued over 100 years ago (U.S. Pat. No. 556,669, Increasing the Flow of Oil Wells, issued to Frasch, H.). At present, hydrochloric acid is still the preferred acid treatment in carbonate formations. For sandstone formations, the preferred fluid is a hydrochloric/hydrofluoric acid mixture.
Again, the major drawback of these acids are that they react too quickly and hence penetrate (as unspent acid) into the formation poorly. Second, they are highly corrosive to wellbore tubular components. Organic acids are a partial response to the limitations of mineral acids. The principal benefit of the organic acids are lower corrosivity and lower reaction rate (which allows greater radial penetration of unspent acid). The organic acids used in conventional treatments are formic acid and acetic acid. Both of these acids are have numerous shortcomings. First, they are far more expensive than mineral acids. Second, while they have a lower reaction rate, they also have a much lower reactivityxe2x80x94in fact, they do not react to completion, but rather an equilibrium with the formation rock is established. Hence one mole of HCl yields one mole of available acid (i.e., H+), but one mole of acetic acid yields substantially less than one mole of available acid.
As evidenced by this discussion, numerous techniques have been proposed/developed to control acid reactivityxe2x80x94i.e., so that the acid does react completely near the wellbore, but remains chemically active as the fluid is propagated radially into the formationxe2x80x94to achieve acceptable axial distribution, and to mitigate corrosion. Each is an imperfect solution at best. Therefore, an acid fluid in which the reactivity could be carefully controlled as the fluid propagates from the wellbore and radially into the formation, which is easy to pump (i.e., does not need to be gelled), which has acceptable axial distribution, and which has low corrosivity, is a long-sought after, and highly desirable goal in acid treatment.
The common denominator of every stimulation technique that comprises the present Invention is that they each involve the use of a remarkable class of compounds generally known as xe2x80x9cionic liquids.xe2x80x9d Ionic liquids are distinguished from (1) xe2x80x9cmolecular liquidsxe2x80x9d (e.g., carbon tetrachloride) and (2) xe2x80x9csolutionsxe2x80x9d which contain dissolved electrolytes (e.g., Na+ Clxe2x88x92 in water) in that, in the case of an ionic liquid, the entire liquid is composed of cations and anionsxe2x80x94i.e., it is a homogeneous liquid having those two components (hence also the term xe2x80x9cmolten saltsxe2x80x9d). Thus, pure water would not qualify as an ionic liquid since it consists of H2O molecules, rather than ions. Nor would an Na+ Clxe2x88x92 solution qualify since it consists of H2O molecules and Na+ and Clxe2x88x92 ions. Ionic liquids shall be discussed in far more detail in the Detailed Description later in the Specification.
Therefore, in the most general sense, the Invention resides in the use of ionic liquids in stimulation and workover operations, and in particular, in matrix acidizing treatments.
As the following text shall illustrate, four primary, distinct modes of action possessed by ionic liquids are exploited in the present Invention. Not all modes of action are implicated in a given stimulation or workover application, though some particular application may rely upon all four modes of action; some rely upon only one. These modes of action are: (1) dissolution by the ionic liquid; (2) heat formation upon ionic liquid generation; (3) ionic liquid as a carrier solvent for a reactive agent; and (4) acid generation by reaction of ionic liquid with water. The first mode of action, dissolution, exploits the excellent solubility characteristics of ionic liquids to dissolve an extraordinarily broad range of materials, both organic (polar, non-polar, and charged, e.g., scleroglucan and xanthan polymer) and inorganic (e.g., calcium carbonate-based rock). The second mode of action relies upon a peculiar feature of the synthesis of ionic liquids, namely that substantial heat is released during ionic liquid formation (depending upon the ionic liquid being synthesized). Indeed, we have found through laboratory testing that the quantity of heat released during the progress of this exothermic reaction is sufficient to melt paraffin, sludge, and wax, which are ubiquitous and also very-difficult-to-remove wellbore contaminants. Third, ionic liquidsxe2x80x94again depending upon the particular species and the solute one has in mindxe2x80x94are excellent (e.g., highly stable, inert) solvents; therefore, they can be used to transport highly reactive substances such as super acids (e.g., HF+SbF5). Fourth, some, though not all ionic liquids generate prodigious quantities of acid upon reaction with water. This mode of action can be exploited in applications that require the introduction of acid into the wellbore. Moreover, more than one of these four mechanisms can be exploited in a single treatment. For instance, an ionic liquid-based fluid of the present Invention can be pumped into a wellbore; the ionic fluid then dissolves portions of the formation (e.g., carbonate) near the wellbore thereby creating alternate flowpaths for hydrocarbon to move from the formation into the wellbore. Next, water can be pumped into the wellbore to contact the ionic liquid, which would result in acid generation. The acid would then further degrade the carbonate as well as the polymer damage (e.g., scleroglucan, starch, xanthanxe2x80x94i.e., drilling fluid residue).
The fluids of the present Invention provide several substantial advantages over state-of-the-art stimulation and workover fluids. First, a dramatic and unusual attribute of the fluids of the present Invention is that when combined with water, an acid is generated. Hence, an ionic liquid of the present Invention can be pumped into the wellbore, followed by waterxe2x80x94i.e., the water and ionic liquid can be combined within the wellbore. The significance of this is that no acid is generated at the surface. Therefore, the pumps, storage tanks, well casings, and so forthxe2x80x94which are extraordinarily expensive to replacexe2x80x94are not damaged due to corrosion caused by acid, as they are in convention acid treatments. Second, even if the water and ionic liquid are combined at the surface and pumped downhole, acid generation is still delayed (i.e. acid generation is slow as evidenced by laboratory results discussed below), which means that more of the acid will reach distal regions of the formation.
A second significant advantage of the present Invention is that acid generation can be carefully controlled. This is because acid does not form until the ionic liquid is combined with water; and therefore, acid generation can be increased or decreased by modifying the rate of addition of either of these components into the wellbore. Indeed, a major limitation of conventional acid treatments (either acid fracturing or matrix stimulation) is that the acid is too quickly consumed once injected into the formation, and so the matrix immediately adjacent to the wellbore is stimulated, but not further beyond the wellbore. Therefore, what is desired is a fluid that does not react completely with the surrounding matrix but will react slowly as it propagates from the wellbore radially into the formation, so that some of the unreacted acid remains at extreme distal locations from the wellbore, where formation stimulation is also desired.
A third significant advantage of the present Invention is that it has a drastically lower corrosivity compared with conventional acid treatments. Acids attack the storage tanks, pumps, as well as wellbore casings. Replacement and repair of these goods is a major expense directly related to acid treatment. Therefore, a corrosion inhibitor is typically added to acid treatment fluids. For instance, dodecylpyridinium chloride and octylpyridinium bromide solutions as proven corrosion inhibitors used in matrix treatment fluids. Generally speaking, the corrosion inhibitor is a significant portion of the total expense of acid treatments. Indeed, upon addition of water to a particularly preferred ionic liquid of the present Invention (e.g., 1-ethyl-3-methylimidazolium tetrachloaluminate) acid is of course generated, along with a pyridinium saltxe2x80x94which is a proven, effective corrosion inhibitor. Therefore, preferred species of the ionic liquids of the present Invention generate their own corrosion inhibitor, and therefore there may often be no need to add an inhibitor. This will result in a major cost advantage of the ionic liquid-based fluids of the present Invention.
Therefore, the present Invention substantially solves these three primary problems that have plagued acid-stimulation techniques since their inception. First, since the acid is generated in situ, or within the formation, rather than at the surface, then acid never contacts the storage tanks, pumps, or (uppermost) well casing, and therefore the acid stimulation techniques of the present Invention have the advantage over conventional techniques of not corroding these materials, which are very costly to replace. Second, since acid generation can be controlled by the rate or extent of water addition (or ionic liquid addition) then acid generation can be controlled in such a way that it is not immediately consumed upon contact with the formation. The purpose of an acid treatment is to remove formation damage along as much of the hydrocarbon flow path as possible. An effective treatment must therefore remove as much damage as possible along the entire flow path (i.e., from the wellbore extending radially into the formation). Using the fluids and techniques of the present Invention, the acid will have a greater penetration distance, therefore extend along a greater portion of the hydrocarbon flow path, and therefore resulting in a more effective treatment. Third, many preferred species of ionic liquids are completely miscible with an organic phase, in preference to an aqueous phase. Therefore, the problem of axial distribution that plagues conventional (HCl) treatment is substantially mitigated.